During production of natural gas from a subsurface gas reservoir, formation pressure of the reservoir decreases as gas is produced from the reservoir. This decreasing formation pressure results in reduced gas production rates from the formation. Despite such reducted production rates, low pressure gas reservoirs can continue to produce significant volumes of gas over long periods of time, even at extremely low pressures.
In order to maximize production rates and ultimate recovery volumes from a low pressure gas reservoir, it is necessary to remove any flow restrictions which might limit gas production. The need to remove such flow restrictions is important in high pressure gas reservoirs, but it is especially critical in producing low pressure gas reservoirs. The removal of flow restrictions from a well producing a low pressure gas formation will help ensure that all producible gas is removed from the formation before gas production operations are ended and the formation is abandoned.
One of the most typical flow restrictions in a low pressure gas well is caused by fluid accumulation in the wellbore. During production of a gas well, condensate, brine, or other wellbore fluids may enter and accumulate in the wellbore. Hydrostatic pressure created by the accumulated fluid reduces gas flow into the wellbore and accordingly, the gas production rate from the well. Although the well may produce some gas capable of moving through the accumulated fluid, the production rate of the well will be reduced when fluid accumulates in the wellbore. If the well cannot produce any gas capable of moving through the accumulated fluid, the gas production will completely cease. In order to remove this occasional accumulation of fluid, artificial lift means, such as gas-lift, are used to move the produced fluid to the ground surface.
During completion of a typical oil or gas well, production casing is extended from the ground surface through the reservoir to be produced. Inside the production casing is a string of pipe called production tubing. An opening called an annulus is formed between the production tubing and casing. By injecting pressurized gas into the annulus and through a downhole valve arrangement, fluids may be lifted up the production tubing to the ground surface for separation and further treating. This fluid lifting is accomplished by the injected gas expanding downhole. As the injected gas moves through the accumulated fluids, the gas expands, lightening the fluid, which helps the fluids move up the production tubing to surface. This use of pressurized gas to remove wellbore fluids in this manner is referred to as gas-lift.
Although gas-lift operations are typically used to lift fluids from oil wells, gas wells producing from low pressure formations can also use a form of gas-lift to remove produced fluids which have accumulated in a wellbore. The present invention is most useful in the removal of such accumulated fluids from a wellbore producing a low pressure gas formation.
In gas-lift operations, the gas that is injected into the production casing is occasionally higher pressure than the formation from which gas is being produced. It is, therefore, necessary to prevent the high pressure gas-lift gas from moving from the production casing into the producing formation. To keep the lift gas from being injected into the formation, a valve, typically in the form of a check valve, is placed near the end of the production tubing string. This check valve, which is also called a standing valve, is designed to allow formation gas and fluid to flow from the producing formation into the tubing when no gas-lift gas is present. When gas-lift gas is injected to assist fluid production through the production tubing, the increased production tubing pressure closes the standing valve to keep the higher pressure gas-lift gas from going into the formation. When gas-lift assistance is no longer necessary, the standing valve is again opened to allow formation gas and fluid to enter into the tubing. Standing valves are widely known and used throughout the oil and gas industry.
Although there are various commercial standing valves available, the typical standing valve severely restricts formation gas and fluid to flow into the tubing from low pressure formations when the valve is opened.
A typical standing valve is composed of a floating ball in a tapered seat arrangement. During operatin of the valve, the floating ball rests on the seat until gas or other fluid is produced from the formation into the tubing. As the fluid flows up the tubing past the standing valve, the fluid lifts the ball off its tapered, sealing seat allowing fluid to enter the production tubing. When fluid has accumulated such that pressure created by the fluid accumulated above the standing valve is equal to the subsurface reservoir pressure, the floating ball valve will rest on the seat and not allow gas or other fluid in the tubing to move up or down through the ball valve seat. At this point, gas is injected into the annulus to remove the fluid that has accumulated above the standing valve.
After the accumulated fluid has been removed, injection of gas-lift gas is discontinued. The floating ball then moves off the seat and the standing valve again allows gas and other fluids into the tubing.
The standard ball and seat type standing valve requires that the produced gas and fluids lift the ball off the seat and move across the ball and valve seat. This flow path past the seat and ball significantly increases pressure drop through the valve and reduces gas production rates. For wells producing high pressure formations, the pressure drop across a standing valve may be acceptable due to other flow restrictions in a producing well. However, for wells producing low pressure formations, the continuous drop across the valve, which may be on the order of 10 pounds per square inch, causes flow restrictions that significantly reduce the production rate of a given well.
The need exists for a standing valve which has less restrictive flow paths to reduce the significant pressure drop experienced through normal standing valves. The present invention accomplishes this through a valve seating device and seating arrangement which provides a large cross-sectional flow area when the valve seating device is not in contact with the seating arrangement. This large cross-sectinal area allows large gas volumes to move through a standing valve arrangement and experience significantly less pressure drop than when the same gas volumes move through a standard ball and seat valve.